In order to optimise the performance of a drilling fluid during a drilling operation the physical and chemical properties of the fluid must be carefully controlled. The rheological properties--viscosity, yield stress and gel strength--of the fluid are of particular importance because they are related to the removal of drilled rock cuttings from the borehole, the holding of rock cuttings and weighting agents in suspension during periods of no circulation, and the removal of rock cuttings and drilled solids by surface solids control equipment. The fluid loss properties of the fluid result in the formation of a filter-cake on permeable rock sections of the wellbore so as to minimise losses of the continuous phase of the fluid to the formation during drilling. Thus, both rheological and fluid loss properties of the drilling fluid combine to prevent an accumulation of drilled solids within the circulating fluid, and so result in an optimum drilling rate of penetration.
A wide variety of organic and polymer additives have found extensive use in water-based drilling fluids, examples of which can be found in Chilingarian, G. V. and Vorabutr, P., "Drilling and drilling fluids", Elsevier Science Publishers B. V. (1983), Gray, G. R. and Darley, H. C. H., "Composition and properties of oil well drilling fluids", Gulf Publishing Company (1981) and "1992-93 Environmental Drilling and Completion Fluids Directory", Offshore/Oilman, September 1992. These additives are used to formulate a fluid with the required viscosity, yield stress, gel strength and fluid loss properties for a particular drilling application. An additional and increasingly important function of organic and polymer additives used in water-based drilling fluids is the stabilisation of water-sensitive rock formations such as shales. Wellbore stabilisation is achieved both by interactions between additives and the wellbore wall to prevent swelling, dispersion and subsequent erosion of shales, and by interactions with drilled cuttings to prevent cuttings dispersion so as to achieve optimum removal of drilled material by surface solids control equipment.
The current standard procedure for field-testing drilling fluids is given in the American Petroleum Institute (API) "Recommended Practice Standard Procedure for Field Testing Drilling Fluids", RP 13B, 12th ed., September 1988. The document defines field procedures for determining both the physical and chemical properties of water-based and oil-based drilling fluids. The API methods for chemical analysis of water-based drilling fluids include determinations of pH, alkalinity and lime content, chloride, calcium, magnesium, calcium sulphate, formaldehyde, sulphide, carbonate and potassium; they do not, though, include any methods for determining the concentration of organic and polymer additives in water-based drilling fluids. However, there are a number of other oilfield publications which have proposed methods for determining certain polymers in drilling fluids.
For example, there are several published methods which are proposed for quantifying the polymer, partially hydrolysed polyacrylamide (PHPA), in drilling fluids. Fraser, L. J., "New method accurately analyzes PHPA's in muds", Oil & Gas Journal, July 1987 proposes a procedure which involves (i) alkaline hydrolysis of a whole mud or mud filtrate sample, (ii) complexation of the ammonia released using a boric acid absorbing solution, and (iii) titration with a standard acid solution. McCulley, L. Z. and Malachosky, E., "A new method for the quantitative determination of the PHPA polymer content of drilling fluids and other aqueous systems", SPE 22580, presented at the 66th Annual Technical Conference & Exhibition, Dallas, October 1991, reviews methods based on an alkaline hydrolysis of the sample, noting that even the vigorous reaction conditions used by Fraser may not be adequate to effect complete conversion due to shielding of the amide groups in the high molecular weight PHPA chain; they also raise an objection to the use of mud filtrate samples for the determination of PHPA in drilling fluids. McCulley et al. propose a method based on a sulphuric acid digestion of the whole mud sample, which results in the total oxidation of organic material and a complete conversion of organic nitrogen to ammonium ions which are subsequently detected using an ammonium ion-selective electrode. These chemical methods may be used to detect the total amount of PHPA in the drilling fluid; however, in order to optimise the system, the effective concentration of PHPA (i.e. the concentration of PHPA which is free to associate with reactive shale formations and thus aid in the stabilisation of the wellbore and drilled cuttings) must be determined, not just the total concentration of PHPA. During drilling, the effective concentration of PHPA may be depleted by at least two mechanisms: (i) by adsorption on the wellbore wall and on newly drilled solids; and (ii) by polymer degradation--e.g. due to shearing through bit nozzles. Traditionally, the industry has used indirect qualitative field methods involving a subjective examination of the `quality` of cuttings passing over the shaker screens to assess the inhibition level of a drilling fluid. If the effective PHPA concentration in the drilling fluid is too low, cuttings will become highly dispersed resulting in an accumulation of drilled solids within the circulating fluid; if the effective PHPA concentration is too high, the polymer can `agglomerate` and `blind` the solids control equipment screens. Williamson, L. D., Javanmardi, K. and Flodberg, K., "Method aids calculation of PHPA depletion rates", Oil & Gas Journal, July 1992 describes a hot rolling dispersion test at the rig site as a method for analysing the effective concentration of PHPA. The analysis depends on the ability of the drilling fluid to inhibit dispersion relative to a standard PHPA salt solution. This article emphasises that the PHPA inhibitor level should be adjusted to correspond with formation reactivity; the field data clearly indicate that the inhibitive performance index of a PHPA drilling fluid decreases as a result of interactions with formations rich in montmorillonite.
Thus, the previously proposed methods for monitoring PHPA in drilling fluids have focused on two general approaches: (i) the development of rather involved chemical techniques to determine the total PHPA concentration; and (ii) the development of indirect methods based on some diagnostic of the inhibitive performance of the fluid. The latter methods are usually based on the ability of the fluid to stabilise cuttings and not necessarily the wellbore. Similar approaches are apparent from reviewing proposed methods for determining other polymers and organics in drilling fluids. Chemical techniques for PHPA determination rely on a specific analysis of amide groups in the analyte polymer; therefore, they rely on a previous evaluation of the degree of hydrolysis of the particular PHPA used to formulate the drilling fluid, and they do not take into account changes in the degree of hydrolysis which may occur as PHPA responds to high temperature alkaline conditions. Many of the range of polymers used to provide the required rheological and fluid loss properties of drilling fluids have very similar functional groups, and, as a result, it is often difficult to develop chemical techniques which are sufficiently specific for the determination of each polymer in complex mixtures.
Previous Patents and other Publications have described methods based on Fourier Transform Infrared (FTIR) spectroscopy for determining the total concentration of both solid and organic/polymer components in water-based drilling fluids (European Pat. Appl. EP 426,232, U.S. Pat. No. 5,161,409, and European Pat. Appl. 507,405) and in oil-based drilling fluids (European Pat. Appl. EP 507,405).
It is widely recognised that the static filtration of drilling fluids containing polymers often results in an enrichment of the polymer in the filter cake and a corresponding depletion in the filtrate. McCulley et al. emphasise that the filtrate obtained from the standard API filtration apparatus is considered to be unsuitable for any truly quantitative procedure for determination of the PHPA concentration in drilling fluids. Hughes, T. L., Jones, T. G. J. and Houwen, O. H., "The chemical composition of CMC and its relationship to the rheology and fluid loss of drilling fluids", SPE 20000, presented at the IADC/SPE Drilling Conference, Houston, March 1990 concludes that the recovery of carboxymethyl cellulose (CMC) in API filtrates obtained from some simple CMC-bentonite fluids is dependent on both the polymer/bentonite ratio of the fluid and on the molecular weight distribution of the polymer.